Methods for stimulating oil or gas production using a viscosified aqueous fluid with a chelating agent to remove scale from wellbore tubulars or subsurface equipment

ABSTRACT

A method for treating a wellbore tubular or subsurface completion equipment to help remove scale is provided. In general, the method comprises the steps of: (A) determining the likelihood of the presence of carbonate scale in the wellbore tubular or subsurface completion equipment; (B) forming or providing a treatment fluid comprising: (i) water; (ii) a chelating agent capable of forming a heterocyclic ring that contains a metal ion attached to at least two nonmetal ions; and (iii) a viscosity-increasing agent; and (C) introducing the treatment fluid into the wellbore tubular or the subsurface completion equipment.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

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REFERENCE TO MICROFICHE APPENDIX

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Technical Field

The invention generally relates to production enhancement to increasehydrocarbon production from a subterranean formation. More particularly,the invention relates to methods of treating downhole wellbore tubularsor subsurface completion equipment for mineral deposits, which depositsare generally referred to as scale, and especially for depositscontaining calcium carbonate.

SUMMARY OF THE INVENTION

According to the invention, a method for treating at least a portion ofa downhole wellbore tubular or subsurface completion equipment isprovided. In general, the method comprises the steps of: (A) determiningthe likelihood of the presence of scale in the wellbore tubular or thesubsurface completion equipment; (B) forming or providing a treatmentfluid comprising: (i) water; (ii) a chelating agent capable of forming aheterocyclic ring that contains a metal ion attached to at least twononmetal ions; and (iii) a viscosity-increasing agent; and (C)introducing the treatment fluid into the wellbore tubular or subsurfacecompletion equipment.

Other and further objects, features and advantages of the presentinvention will be readily apparent to those skilled in the art when thefollowing description of the preferred embodiments is read inconjunction with the accompanying drawings

DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT

Scale can be comprised of various mineral component deposits that canform over the inner walls of downhole casing, production tubing, andcompletion equipment, such as valves, gas-lift mandrels, and fluidpumps. Scale can be deposited along water paths in a subterraneanformation, through wellbore tubulars, to surface equipment and surfacetubulars. The scale can become so voluminous that it clogs the downholewellbore tubulars or downhole equipment.

Scale in the oil field environment can be formed as a result of mixingtwo incompatible waters downhole to create produced water that isoversaturated with scale-forming minerals. Scale can also be formed whenthe state of the water being produced is changed such that thesolubility limit for one or more mineral components is exceeded. Thesolubility limit of each mineral component in an aqueous solution has acomplex relationship to several factors, including temperature,pressure, the concentrations of other mineral components in solution,and pH. In general, but not for all minerals, a decrease in temperaturetends to decrease the water solubility of the mineral. Similarly, asubstantial decrease in pressure tends to decrease the water solubilityof a mineral. Further, the solubility of a mineral can be impacted bythe concentrations of other minerals in the solution. The solubility ofcertain minerals, such as carbonate minerals, is also increased in thepresence of acid gases such as carbon dioxide and hydrogen sulfide,where carbonate solubility tends to increase as with increasing acidity.Carbon dioxide and hydrogen sulfide at high pressure can make waterquite acidic. Water containing such gases produced from a subterraneanformation containing carbonate rock can have a high concentration ofdissolved carbonate.

In producing water from a subterranean formation, the temperature tendsto decrease and the pressure can also be decreased, both of whichchanges can contribute to precipitating minerals from the water to formscale in downhole wellbore tubulars and equipment. In the case ofreleasing pressure, carbon dioxide or hydrogen sulfide may also bereleased, allowing the pH of the produced water to rise. Such changescan cause scale deposits. Sometimes so much scale can be deposited thatthe scale blocks the fluid flow path through the downhole wellboretubulars or equipment, and even downstream in surface tubulars andequipment.

Although the solubility limits of various minerals have complexrelationships with temperature, pressure, the concentrations of otherminerals in the solution, and pH, such relationships are becomingincreasingly well known and understood and it is possible to makecomputer models of downhole conditions that are likely to produce scaledeposits.

In general, the purpose of this invention is to improve delivery of achelating agent and the flowing back of the fluid for scale removal byincreasing the viscosity of the treatment fluid. A chelating agent canbe utilized to help dissolve and remove carbonates and other mineralsfrom a wellbore tubular. The concentration of the chelating agent issufficient to help dissolve a substantial amount of carbonate material.The treatment fluid containing the chelating agent includes aviscosity-increasing agent to help with placement of the treatment fluidand to help carry out some scale with the flow back of the treatmentfluid. When the viscosity of the fluid is increased or gelled, thetreatment fluid can provide better coverage and carry suspendedparticles, including small pieces of scale. The treatment fluid can be asingle fluid that dissolves calcium/magnesium/iron carbonate solids in awellbore tubular at a controlled rate and under a wide range ofconditions, especially over a broad range of pH and time. The inventioncan be advantageous because it can provide methods for treating wellboretubulars for such purposes using treatment fluids that are non-acidcontaining and non-corrosive.

The treatment methods according to the invention are expected to beeffective for applications associated with: removal of carbonate scalefrom downhole wellbore tubulars or subsurface wellbore completionequipment, particularly where the use of strongly acidic fluids might beproblematic, for example, in high-temperature formations due to reactionrates, or due to corrosion, etc.

As used herein, the words “comprise,” “has,” and “include” and allgrammatical variations thereof are each intended to have an open,non-limiting meaning that does not exclude additional elements or steps.

In general, the new approach is a method for treating at least a portionof a downhole wellbore tubular or subsurface equipment, the methodcomprising the steps of: (A) determining the likelihood of the presenceof scale in the downhole wellbore tubular or subsurface equipment; (B)forming or providing a treatment fluid comprising: (i) water; (ii) achelating agent capable of forming a heterocyclic ring that contains ametal ion attached to at least two nonmetal ions; and (iii) aviscosity-increasing agent; and (C) introducing the treatment fluid intothe wellbore tubular or subsurface equipment.

Determining the likelihood of the presence of carbonate scale in thedownhole wellbore tubular or subsurface equipment is an important stepin the remediation process according to the invention.

Scale in wellbore tubulars or subsurface completion equipment tends tooccur as a thick layer on the inside wall of the tubular or completionequipment. The scale lowers the production rate from the wellbore byincreasing the surface roughness of the inner wall of the tubular orequipment and reducing the cross-sectional flow area. The pressurerequired to push a fluid through the tubular area increases, flowdecreases, and production decreases. In an injection well, scale damageis usually caused by temperature-activated autoscaling. In addition,incompatible mixing of different waters can occur when injection watercontacts either natural formation water or completion brine. Scaleformed in an injection well can decrease the effectiveness of awater-flood strategy. In a production well, scale damage can occur witha change in state in the produced water, for example, a decrease intemperature and pressure, or an increase in pH from a relatively acidicstate. Regardless of the particular origin or cause of the scale, areduction in fluid flow can be an indicator of the build of scale.

According to another embodiment of the invention, production analysiscan indicate wellbore tubing scale, especially if a well suddenlydemonstrates tubing constraints that were not present during earlyproduction.

The onset of water production is often a sign of potential scaleproblems, especially if it coincides with a simultaneous reduction inoil production. Tracking water chemistry and in particular the dissolvedion content of the produced water can be important indicators for thelikelihood of scale formation. Dramatic changes in the concentrations ofscaling ions, especially if coinciding with reduced oil production andincreased water cut, can signal that injection water has broken throughand scale is beginning to form. A review of the well history in responseto any previous chemical interventions, such as acid treatments, canhelp in the making of these interpretations.

Determining the likelihood of the presence of carbonate scale can alsobe obtained by taking samples of downhole scale or X-ray evidence fromcore analysis. Gamma ray log interpretation often indicates bariumsulfate scale because naturally occurring radioactive strontium tends toprecipitate with this type of scale mineral.

Wells with intelligent completions and permanent monitoring systems canalso be designed to detect changes in water chemistry. Downhole scalesensors and permanent monitoring applications are areas of activeresearch.

According to another embodiment of the invention, chemical modeling canbe used to determine the likelihood of the presence of scaling based ontracking water analysis for mineral concentrations and other conditions,such as temperature, pressure, pH, and gas-phase compositions. Theresults of such techniques can be used to indicate the need for scaletreatment of the downhole wellbore tubulars or subsurface equipment.

It is believed that the chelating agent in the treatment fluid can reactwith and dissolve calcium carbonate, magnesium carbonate, dolomite, ironcarbonate, and similar materials of scale in the wellbore tubular,helping to re-open up the tubular, whereby hydrocarbon productionthrough the tubular can be enhanced. CaCO₃ and CaMg(CO₃)₂ mayprecipitate from water as scale in wellbore tubulars. Typical scales areof calcium carbonate, calcium sulfate, barium sulfate, strontiumsulfate, iron sulfide, iron oxides, iron carbonate, various silicatesand phosphates and oxides, or any of a number of compounds insoluble orslightly soluble in water. Although it may not be expected to dissolveall of the components of scale, the chelating agent can be helpful inremoving calcium carbonate, magnesium carbonate, dolomite, ironcarbonate, and similar materials of scale.

As used herein, to chelate means to combine a metal ion with a chemicalcompound to form a ring. “The adjective chelate, derived from the greatclaw or chela (chely-Greek) of the lobster or other crustaceans, issuggested for the caliper like groups which function as two associatingunits and fasten to the central atom so as to produce heterocyclicrings.” Sir Gilbert T. Morgan and H. D. K. Drew [J. Chem. Soc., 1920,117, 1456].

Preferably, the water further includes a water-soluble inorganic saltdissolved therein. The purpose of the inorganic salt can be, forexample, to weight the water of the treatment fluid or to make thetreatment fluid more compatible and less damaging to the subterraneanformation. It should be understood, of course, that a source of at leasta portion of the water and the inorganic salt can be selected from thegroup consisting of natural or synthetic brine or seawater. Inorganicsalt or salts can also be mixed with the water of the treatment fluid toartificially make up or increase the inorganic salt content in thewater. Alternatively for these types of purposes, a water-soluble saltreplacement can be utilized such as tetramethyl ammonium chloride (TMAC)and similar organic compounds.

It is a particular advantage of the method according to the invention tobe able to help remove carbonate and similar materials without the useof strongly acidic treatment compositions, that is, without the use oftreatment compositions having a pH less than 2. According to a preferredembodiment of the invention, the pH of the treatment fluid is equal toor greater than 2, which is above the pH of strong inorganic acids thathave been used to help dissolve and remove carbonate materials from theformation.

More preferably, according to the invention, the pH of the treatmentfluid is equal to or greater than 5, which is well above the pH of spentacid fluids used for the purpose of removing carbonate, where the pH ofan acid fluid is typically less than about 3.5. The compositions of thepresent invention can be used to help dissolve and remove carbonatematerials from the formation with less acidic compositions. In someapplications, acidic compositions can be damaging to the well orhydrocarbon production.

Most preferably, according to the invention, the pH of the treatmentfluid is in the range of 6-12, which can be used to avoid or reduce theuse of substantially acidic compositions in treating the formation. Itis important to note, of course, that different chelating agents workbetter in certain pH ranges than other ranges. Some chelating agents canbe effective in the higher pH ranges. One skilled in the art would alsorecognize the obvious advantage of using a non-acid fluid may reduce therate of corrosion.

In particular, the chelating agent is selected to be effective forchelating at least calcium ions. It is also highly desirable that thechelating agent is soluble in distilled water at standard temperatureand pressure at a concentration of at least 0.2 mole-equivalent forcalcium ions per liter of the distilled water. As a test for whether ornot the chelating agent would be effective for use in the presentinvention, it is believed that a solution of the chelating agent at aconcentration of 0.2 mole-equivalent for calcium ions per liter of thedistilled water should be effective for chelating at least 0.1 molecalcium ions per liter. Preferably, the test solution is effective whenadjusted to have a pH in the range of 5-6. More preferably, the testsolution is effective when adjusted to have a pH in the range of 6-8.One skilled in the art would recognize that similar tests can beperformed for other ions such as magnesium, iron, etc.

There are numerous examples of suitable chelating agents. For variousreasons including effectiveness, ready availability, and economicalcost, the chelating agent is preferably selected from the groupconsisting of ethylenediamine tetraacetic acid (“EDTA”),nitrilotriacetic acid (“NTA”), hydroxyethylethylenediaminetriacetic acid(“HEDTA”), diethylenetriaminepentaacetic acid (“DTPA”),propylenediaminetetraacetic acid (“PDTA”),ethylenediaminedi(o-hydroxyphenylacetic) acid (“EDDHA”), a sodium orpotassium salt of any of the foregoing, dicarboxymethyl glutamic acidtetrasodium salt (“GLDA”), a derivative of any of the foregoing or anycombination in any proportion thereof. It is to be understood, ofcourse, that a derivative may be employed provided that the substitutionof an atom or group of atoms in the parent compound for another atom orgroup of atoms does not substantially impair the function of thederivative relative to the parent compound. A derivative would alsoinclude compounds that do not have the functionality, but would regainfunctionality due to some process in use such as a reaction, hydrolysis,degradation, etc. The chelating agent is preferably at a concentrationof at least 0.01% by weight of the water. More preferably, the chelatingagent is at a concentration in the range of 1% to 80% by weight of thewater.

The viscosity-increasing agent would typically comprise a polymericmaterial. For various reasons including effectiveness, readyavailability, and economical cost, the polymeric material is preferablyselected from the group consisting of: guar gum and its derivatives,cellulose derivatives, welan gum, xanthan biopolymer and itsderivatives, diutan and its derivatives, scleroglucan and itsderivatives, succinoglycan biopolymer and its derivatives, and anycombination of any of the foregoing in any proportion. A preferredpolymer is of the nature taught in U.S. Patent Application Serial No.20060014648, which is incorporated herein by reference in its entirety.

According to another aspect of the invention, the viscosity-increasingagent can advantageously comprise a viscoelastic surfactant. Oneperceived advantage of a surfactant gel is that it has much lesspotential for leaving a polymer residue. The viscoelastic surfactant maycomprise any viscoelastic surfactant known in the art, any derivativethereof, or any combination thereof. As used herein, the term“viscoelastic surfactant” refers to a surfactant that imparts or iscapable of imparting viscoelastic behavior to a fluid due, at least inpart, to the association of surfactant molecules to form viscosifyingmicelles. These viscoelastic surfactants may be cationic, anionic,nonionic, or amphoteric/zwitterionic in nature.

The viscoelastic surfactants may comprise any number of differentcompounds, including methyl ester sulfonates (e.g., as described in U.S.patent application Ser. Nos. 11/058,660, 11/058,475, 11/058,612, and11/058,611, filed Feb. 15, 2005, each of which is assigned toHalliburton Energy Services, Inc., the relevant disclosures of which areincorporated herein by reference), hydrolyzed keratin (e.g., asdescribed in U.S. Pat. No. 6,547,871 issued Apr. 15, 2003 to HalliburtonEnergy Services, Inc., the relevant disclosure of which is incorporatedherein by reference), sulfosuccinates, taurates, amine oxides,ethoxylated amides, alkoxylated fatty acids, alkoxylated alcohols (e.g.,lauryl alcohol ethoxylate, ethoxylated nonyl phenol), ethoxylated fattyamines, ethoxylated alkyl amines (e.g., cocoalkylamine ethoxylate),betaines, modified betaines, alkylamidobetaines (e.g., cocoamidopropylbetaine), quaternary ammonium compounds (e.g., trimethyltallowammoniumchloride, trimethylcocoammonium chloride), derivatives of any of theforegoing, and any combinations of any of the foregoing in anyproportion.

Suitable viscoelastic surfactants may comprise mixtures of severaldifferent compounds, including but not limited to: mixtures of anammonium salt of an alkyl ether sulfate, a cocoamidopropyl betainesurfactant, a cocoamidopropyl dimethylamine oxide surfactant, sodiumchloride, and water; mixtures of an ammonium salt of an alkyl ethersulfate surfactant, a cocoamidopropyl hydroxysultaine surfactant, acocoamidopropyl dimethylamine oxide surfactant, sodium chloride, andwater; mixtures of an ethoxylated alcohol ether sulfate surfactant, analkyl or alkene amidopropyl betaine surfactant, and an alkyl or alkenedimethylamine oxide surfactant; aqueous solutions of an alpha-olefinicsulfonate surfactant and a betaine surfactant; and any combination ofthe foregoing mixtures in any proportion. Examples of suitable mixturesof an ethoxylated alcohol ether sulfate surfactant, an alkyl or alkeneamidopropyl betaine surfactant, and an alkyl or alkene dimethylamineoxide surfactant are described in U.S. Pat. No. 6,063,738, issued May16, 2000 to Halliburton Energy Services, Inc., the relevant disclosureof which is incorporated herein by reference. Examples of suitableaqueous solutions of an alpha-olefinic sulfonate surfactant and abetaine surfactant are described in U.S. Pat. No. 5,897,699, therelevant disclosure of which is incorporated herein by reference.Examples of commercially-available viscoelastic surfactants suitable foruse in the present invention may include, but are not limited to,Mirataine BET-O 30™ (an oleamidopropyl betaine surfactant available fromRhodia Inc., Cranbury, N.J.), Aromox APA-T™ (an amine oxide surfactantavailable from Akzo Nobel Chemicals, Chicago, Ill.), Ethoquad O/12 PG™(a fatty amine ethoxylate quat surfactant available from Akzo NobelChemicals, Chicago, Ill.), Ethomeen T/12™ (a fatty amine ethoxylatesurfactant available from Akzo Nobel Chemicals, Chicago, Ill.), EthomeenS/12™ (a fatty amine ethoxylate surfactant available from Akzo NobelChemicals, Chicago, Ill.), and Rewoteric AM TEG™ (a tallowdihydroxyethyl betaine amphoteric surfactant available from DegussaCorp., Parsippany, N.J.).

According to a preferred embodiment of the invention, theviscosity-increasing agent is at a concentration in the treatment fluidthat is at least sufficient to make the viscosity of the treatment fluidgreater than water. More preferably, the viscosity-increasing agent isat a concentration in the treatment fluid that is sufficient to make theviscosity of the treatment fluid greater than 5 cP when measured at 511reciprocal seconds on a Fann 35A model viscometer with a number 1 springand bob. More preferably, the viscosity-increasing agent is at aconcentration in the treatment fluid that is sufficient to make theviscosity of the treatment fluid in the range of 10 cP to 100 cP whenmeasured at 511 reciprocal seconds on a Fann 35A model viscometer with anumber 1 spring and bob.

According to another preferred embodiment according to the invention,the viscosity-increasing polymeric agent is at a concentration of atleast 0.05% by weight of the water. More preferably, theviscosity-increasing agent is at a concentration in the range of 0.05%to 10% by weight of the water.

It is contemplated that it will sometimes be desirable to furtherincrease the viscosity of the treatment fluid. One technique for doingso is to crosslink a polymeric viscosity-increasing agent. According tosuch an embodiment of the invention, the treatment fluid furthercomprises a crosslinking agent to crosslink the polymeric material ofthe viscosity-increasing agent. A multitude of crosslinking agents forsuch purposes are known in the art. Preferably, the crosslinking agentis selected from the group consisting of: borate releasing compounds, asource of titanium ions, a source of zirconium ions, a source ofantimony ions, a source of aluminum ions, a source of periodate ions, asource of permanganate ions, and any combination thereof in anyproportion. According to a preferred embodiment, the crosslinking agentis at a concentration of at least 0.025% by weight of the water.According to a more preferred embodiment of the invention, thecrosslinking agent is at a concentration in the range of 0.025% to about1% by weight of the water.

According to a preferred embodiment of the invention, the treatmentfluid is allowed a sufficient time to attack the scale in the wellboretubular.

According to another preferred embodiment of the invention, thetreatment fluid is flowed back from the well without breaking theviscosity of the fluid. The purpose of the maintaining the viscosity ofthe treatment fluid during a step of flowing back of the treatment fluidis to help carry particles and pieces of the scale that may be loosenedfrom the scale layers but not completely dissolved by the treatmentfluid.

It is contemplated that the methods according to the invention caninclude foaming of the treatment fluid. According to these embodiments,the treatment fluid further comprises: an additive for foaming. Thetreatment fluid may be formed at a remote location and provided to thewell site for the treatment method, or it can be formed locally at thewell site. The treatment fluid preferably further comprises: asufficient gas to form a foam. As used herein, foam also refers tocommingled fluids. Preferably, the gas would be mixed with the otherconstituents of the treatment fluid at the well site to form a foamed orco-mingled fluid. According to a preferred embodiment of the invention,the gas is selected from the group consisting of: air, CO₂, nitrogen,and any combination thereof in any proportion. In applications of themethod utilizing a gas, typically, the gas is at a concentration in therange of 5% to 95% by volume of the water.

According to one aspect of the methods of the invention, the step ofintroducing the treatment fluid into the wellbore further comprises:introducing the treatment fluid at a rate and pressure below thefracture gradient of the subterranean formation.

According to yet another aspect of the methods of the invention, themethods further comprise the step of: applying an afterflush fluid tothe portion of the wellbore tubular. For example, the afterflush fluidcan comprise: water, a gas, a brine, a hydrocarbon, or a mixturethereof.

An example of a treatment fluid for use in the methods according to theinvention was formed as shown in the following Table 1:

TABLE 1 Component Per 200 ml Per 1000 gallons Water 157.6 ml 788 US galsH4EDTA 98% 46.61 g 1987 lbs Potassium Hydroxide Solid 96% 20.95 g 870lbs Xanthan 0.96 g 40 lb/Mgal

The rheological properties of the example composition were measured on aFann Model 35 A viscometer as shown in the following Table 2:

TABLE 2 300 rpm 600 rpm Dial Reading at room temperature 21 29 DialReading at room temperature after 4 hours 29 35 at 175° F.

Therefore, the methods of the present invention are well adapted tocarry out the objects and attain the ends and advantages mentioned aswell as those that are inherent therein. While numerous changes may bemade by those skilled in the art, such changes are encompassed withinthe spirit of this invention as defined by the appended claims.

1. A method for treating a downhole wellbore tubular or subsurfacecompletion equipment, the method comprising the steps of: (A)determining the likelihood of the presence of scale in the downholewellbore tubular or subsurface completion equipment; (B) forming orproviding a treatment fluid comprising: (i) water; (ii) a chelatingagent capable of forming a heterocyclic ring that contains a metal ionattached to at least two nonmetal ions; and (iii) a viscosity-increasingagent; and (C) introducing the treatment fluid into the downholewellbore tubular or the subsurface completion equipment.
 2. The methodaccording to claim 1, wherein the pH of the treatment fluid is equal toor greater than
 2. 3. The method according to claim 1, wherein the pH ofthe treatment fluid is equal to or greater than
 5. 4. The methodaccording to claim 1, wherein the pH of the treatment fluid is in therange of 6-12.
 5. The method according to claim 1, wherein the chelatingagent is effective for chelating at least calcium ions.
 6. The methodaccording to claim 1, wherein the chelating agent is soluble indistilled water at standard temperature and pressure at a concentrationof at least 0.2 mole-equivalent for calcium ions per liter of thedistilled water.
 7. The method according to claim 6, wherein a testsolution of the chelating agent at a concentration of 0.2mole-equivalent for calcium ions per liter of the distilled water iseffective for chelating at least 0.1 mole calcium ions from calciumcarbonate per liter.
 8. The method according to claim 7, wherein priorto exposing the test solution of the chelating agent to the calciumcarbonate, the test solution is adjusted to have a pH in the range of5-6.
 9. The method according to claim 1, wherein the chelating agent isselected from the group consisting of ethylenediamine tetraacetic acid(“EDTA”), nitrilotriacetic acid (“NTA”),hydroxyethylethylenediaminetriacetic acid (“HEDTA”),diethylenetriaminepentaacetic acid (“DTPA”), propylenediaminetetraaceticacid (“PDTA”), ethylenediaminedi(o-hydroxyphenylacetic) acid (“EDDHA”),a sodium or potassium salt of any of the foregoing, dicarboxymethylglutamic acid tetrasodium salt (“GLDA”), a derivative of any of theforegoing, or any combination of any of the foregoing in any proportion.10. The method according to claim 1, wherein chelating agent is at aconcentration in the range of 1 to 80% by weight of the water.
 11. Themethod according to claim 1, wherein the viscosity-increasing agentcomprises a polymeric material.
 12. The method according to claim 11,wherein the polymeric material is selected from the group consisting of:guar gum and its derivatives, cellulose derivatives, welan gum, xanthanbiopolymer and its derivatives, diutan and its derivatives, scleroglucanand its derivatives of succinoglycan biopolymer and its derivatives, andany combination thereof any of the foregoing in any proportion.
 13. Themethod according to claim 1, wherein the viscosity-increasing agentcomprises a viscoelastic surfactant.
 14. The method according to claim13, wherein the viscoelastic surfactant is selected from the groupconsisting of: methyl ester sulfonates, sulfosuccinates, taurates, amineoxides, ethoxylated amides, alkoxylated fatty acids, alkoxylatedalcohols, lauryl alcohol ethoxylate, ethoxylated nonyl phenol,ethoxylated fatty amines, ethoxylated alkyl amines, cocoalkylamineethoxylate, betaines, modified betaines, alkylamidobetaines,cocoamidopropyl betaine, quaternary ammonium compounds,trimethyltallowammonium chloride, trimethylcocoammonium chloride, anammonium salt of an alkyl ether sulfate, a cocoamidopropyl dimethylamineoxide, cocoamidopropyl hydroxysultaine, tallow dihydroxyethyl betaine,derivatives of any of the foregoing, and any combination of theforegoing in any proportion.
 15. The method according to claim 1,wherein the viscosity-increasing agent is at a concentration in thetreatment fluid that is at least sufficient to make the viscosity of thetreatment fluid greater than 5 cP when measured at 511 reciprocalseconds on a Fann 35A model viscometer with a number 1 spring and bob.16. The method according to claim 1, wherein the viscosity-increasingagent is at a concentration in the range of 0.05% to 10% by weight ofthe water.
 17. The method according to claim 1, wherein the treatmentfluid further comprises: an additive for foaming.
 18. The methodaccording to claim 1, wherein the step of introducing the treatmentfluid into the wellbore further comprises: introducing the treatmentfluid at a rate and pressure below the fracture gradient of thesubterranean formation.
 19. A method for treating at least a portion ofa downhole wellbore tubular or subsurface completion equipment, themethod comprising the steps of: (A) determining the likelihood of thepresence of scale in the wellbore tubular or the subsurface completionequipment; (B) forming or providing a treatment fluid comprising: (i)water; (ii) a chelating agent capable of forming a heterocyclic ringthat contains a metal ion attached to at least two nonmetal ions,wherein the chelating agent is effective for chelating at least calciumions; and (iii) a viscosity-increasing agent; wherein the pH of thetreatment fluid is equal to or greater than 5; and (C) introducing thetreatment fluid into the wellbore tubular or the subsurface completionequipment.
 20. A method for treating at least a portion of a downholewellbore tubular or subsurface completion equipment, the methodcomprising the steps of: (A) determining the likelihood of the presenceof scale; (B) forming or providing a treatment fluid comprising: (i)water; (ii) a chelating agent capable of forming a heterocyclic ringthat contains a metal ion attached to at least two nonmetal ions,wherein the chelating agent is effective for chelating at least calciumions, and wherein the chelating agent is soluble in distilled water atstandard temperature and pressure at a concentration of at least 0.2mole-equivalent for calcium ions per liter of the distilled water, andwherein chelating agent is at a concentration in the range of 1 to 80%by weight of the water; and (iii) a viscosity-increasing agent; whereinthe pH of the treatment fluid is equal to or greater than 5; and (C)introducing the treatment fluid into the wellbore tubular or thesubsurface completion equipment.